The retrieval of desired fluids, such as hydrocarbon based fluids, is pursued in subsea environments. Production and transfer of fluids from subsea wells relies on subsea installations, subsea flow lines and other equipment.
Shown in FIG. 1 is a schematic view of a prior art subsea installation 10. The subsea installation 10 comprises a subsea tree 12 formed of a subsea wellhead 14, which may include a Christmas tree, coupled to a subsea well 16 having a wellbore 18. The illustrated subsea tree 12 further comprises a subsea lubricator 20 and a lubricating valve 22 that may be deployed directly above the subsea wellhead 14. Lubricating valve 22 can be used to close the wellbore 18 during certain intervention operations, such as tool change outs. The subsea tree 12 also includes a blowout preventer 24 positioned below the lubricating valve 22 and may comprise one or more cut-and-seal rams 25 able to cut through the interior of the subsea installation 10 and seal off the subsea installation 10 during an emergency disconnect. The subsea tree 12 also may comprise a latch 26, a retaining valve 27 and a second blowout preventer 28 positioned above the blowout preventer 24 and a spanner 34 positioned above the second blowout preventer 28. The subsea installation 10 also includes (1) a riser 36 extending from the second blowout preventer 28 to the surface, (2) a hydraulic pod 38 positioned inside the riser 36 above the spanner 34, and (3) a tubing string 40 positioned inside the riser 36.
One of the more difficult problems associated with the wellbore 18 is to communicate measured data between one or more locations down the wellbore 18 and the surface, or between downhole locations themselves. For example, in the oil and gas industry it is desirable to communicate data generated downhole to the surface during operations such as drilling, perforating, fracturing, and drill stem or well testing; and during production operations such as reservoir evaluation testing, pressure and temperature monitoring. Communication is also desired to transmit intelligence from the surface to downhole tools or instruments to effect, control or modify operations or parameters.
Accurate and reliable downhole communication may be beneficial when complex data comprising a set of measurements or instructions is to be communicated, i.e., when more than a single measurement or a simple trigger signal has to be communicated. For the transmission of complex data it is often desirable to communicate encoded digital signals.
Downhole testing is traditionally performed in a “blind fashion”: downhole tools and sensors are deployed in the subsea well 16 at the end of the tubing string 40 for several days or weeks after which they are retrieved at surface. During the downhole testing operations, the sensors may record measurements that will be used for interpretation once retrieved at surface. It is after the tubing string 40 is retrieved that the operators will know whether the data are sufficient and not corrupted. Similarly when operating some of the downhole testing tools from surface, such as tester valves, circulating valves, packers, samplers or perforating charges, the operators do not obtain a direct feedback from the downhole tools.
In this type of downhole testing operations, the operator can greatly benefit from having a two-way communication between surface and downhole. However, it can be difficult to provide such communication using a cable inside the tubing string 40 because the cable would limit the flow diameter and involves complex structures to pass the cable from the inside to the outside of the tubing string 40. A cable inside the tubing string 40 is also an additional complexity in case of emergency disconnect for an offshore platform. Space outside the tubing string 40 is limited and a cable can easily be damaged.
A number of proposals have been made for wireless telemetry systems based on acoustic and/or electromagnetic communications. Examples of various aspects of such wireless telemetry systems can be found in: U.S. Pat. Nos. 5,050,132; 5,056,067; 5,124,953; 5,128,901; 5,128,902; 5,148,408; 5,222,049; 5,274,606; 5,293,937; 5,477,505; 5,568,448; 5,675,325; 5,703,836; 5,815,035; 5,923,937; 5,941,307; 5,995,449; 6,137,747; 6,147,932; 6,188,647; 6,192,988; 6,272,916; 6,320,820; 6,321,838; 6,912,177; EP0550521; EP0636763; EP0773345; EP1076245; EP1193368; EP1320659; EP1882811; WO96/024751; WO92/06275; WO05/05724; WO02/27139; WO01/3 9412; WO00/77345; WO07/095111.
The tubing string 40 can be constructed of a plurality of tubing sections that are connected together using threaded connections at both ends of the tubing sections. The tubing sections can have uniform or non-uniform pipe lengths. With respect to the non-uniform lengths, this may be caused by the tubing sections being repaired by cutting part of the connection to re-machine the threads. The uniformity or non-uniformity of the tubing lengths can affect the way in which acoustic messages propagate along the tubing string 40.
An acoustic telemetry system is a 2-way wireless communication system between downhole and surface, using acoustic wave propagation along steel pipes and the bottom hole assembly (“BHA”). One modulation scheme used in the acoustic telemetry system uses a single carrier frequency with a phase modulation (QPSK). The carrier frequency may be between 1 and 5 kHz. The frequency width of such modulation is rather narrow, ranging from ˜10 Hz at low bit rate to ˜50 Hz at high bit rate.
In offshore operations multiple acoustic repeaters are positioned on the tubing string 40 positioned within the subsea well 16. A last acoustic repeater is positioned on the tubing string 40 above the sea bed, and connected to surface through an electric cable. This last acoustic repeater is subjected to noise coming from above: The tubing string 40 and the riser 36 are flexible and subjected to currents, thus generating impact or friction noise. Such noise propagates down along the tubing string 40 and may overwhelm the signal coming from downhole and attenuated by the propagation through the equipment of the subsea tree 12.
One possible solution to this problem, presently used by competition, is to position the last acoustic repeater within the subsea tree 12, above the latch 26 and below the retainer valve 27. This reduces to some extent the noise level since the noise has to propagate through heavy pieces of equipment located above such as the retainer valve 27. However, space is at a premium inside the subsea tree 12 which implies an expensive mechanical redesign of the last acoustic repeater. In addition, the filtering effect of the retainer valve 27 is not optimum: assuming the retainer valve 27 can be modeled as a piece of pipe with a larger diameter (13″) and a length of 1 m, connected to the 5″ diameter pipe, the frequency dependent acoustic attenuation is at most 15 dB.
It is desirable to have a subsea installation in which the last acoustic repeater is positioned on the tubing string above the subsea tree while avoiding the noise within the tubing string and coming from above the last acoustic repeater. It is to such an improved subsea installation that the present disclosure is directed.